EP2900900B1 - Sekundäres system und verfahren zum aktivieren einer bohrlochvorrichtung - Google Patents

Sekundäres system und verfahren zum aktivieren einer bohrlochvorrichtung Download PDF

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Publication number
EP2900900B1
EP2900900B1 EP13840432.2A EP13840432A EP2900900B1 EP 2900900 B1 EP2900900 B1 EP 2900900B1 EP 13840432 A EP13840432 A EP 13840432A EP 2900900 B1 EP2900900 B1 EP 2900900B1
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EP
European Patent Office
Prior art keywords
down hole
annular sleeve
base pipe
activation
sleeve
Prior art date
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Application number
EP13840432.2A
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English (en)
French (fr)
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EP2900900A4 (de
EP2900900A1 (de
Inventor
Nicholas Frederick BUDLER
Frank Acosta
Kumaran PALANIVEL
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Halliburton Energy Services Inc
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Halliburton Energy Services Inc
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Publication of EP2900900A1 publication Critical patent/EP2900900A1/de
Publication of EP2900900A4 publication Critical patent/EP2900900A4/de
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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B23/00—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/13—Methods or devices for cementing, for plugging holes, crevices or the like
    • E21B33/14—Methods or devices for cementing, for plugging holes, crevices or the like for cementing casings into boreholes

Definitions

  • the present invention relates to systems and methods used in down hole applications. More particularly, the present invention relates to a secondary or contingency system for initiating a down hole operation such as opening a cementer or setting a down hole tool when a primary system for initiating the down hole operation fails.
  • down hole tools such as well packers
  • a tubular conveyance such as a work string, casing string, or production tubing.
  • the purpose of the well packer is not only to support the production tubing and other completion equipment, such as sand control assemblies adjacent to a producing formation, but also to seal the annulus between the outside of the tubular conveyance and the inside of the well casing or the wellbore itself. As a result, the movement of fluids through the annulus and past the deployed location of the packer is substantially prevented.
  • Well packers are designed to be set using a variety of methods, including electronics, pressure-setting, mechanical shifting, and the like. Although the specific reasons can vary, these well packers are each subject to failure or malfunction. The time and effort required to deal with such failures can be extremely costly.
  • WO 99/05393 relates to the secondary means for closing a bypass valve in the event that the primary means for closing the bypass valve fails to operate.
  • the bypass valve comprises a body having a bore extending therethrough, an aperture adapted to allow fluid communication between the bore and a chamber defined in the body; and an aperture adapted to allow fluid communication between the chamber and the exterior of the bypass valve. Fluid communication between the chamber and the bypass valve exterior is permitted when a piston located in the chamber is in a first position, but is not permitted when the piston is in a second position.
  • the present invention relates to systems and methods used in down hole applications. More particularly, the present invention relates to a secondary or contingency system for initiating a down hole operation such as opening a cementer or setting a down hole tool when a primary system for initiating the down hole operation fails.
  • a system for initiating a down hole operation in a wellbore includes a primary activation system including a moveable member that is movable to open a port to afford fluid communication between a first chamber and a second chamber to thereby initiate the down hole operation.
  • the system also includes a secondary activation system for performing the down hole operation when the primary activation system fails.
  • the secondary activation system includes a passageway between the first chamber and the second chamber, and a rupture member positioned in the passageway.
  • the rupture member has a first side exposed to the first chamber, a second side exposed to the second chamber, and a threshold pressure differential between the first side and the second side at which the rupture member ruptures to afford fluid communication between the first chamber and the second chamber to thereby initiate the down hole operation.
  • a system for initiating a down hole operation in a wellbore includes a body and a rupture member.
  • the body includes an inner surface, an outer surface, a first end, and a second end.
  • the body defines a passageway extending between the inner surface and the outer surface, and at least a portion of the body is configured to move during a primary activation operation to initiate the down hole operation.
  • the rupture member is positioned in the passageway and configured to initiate the down hole operation when the primary activation operation fails.
  • the rupture member has a threshold pressure differential at which the rupture member ruptures to permit fluid flow through the passageway and to thereby initiate the down hole operation.
  • a method for initiating a down hole operation in a wellbore includes positioning a trigger member in the wellbore and performing a primary activation operation configured to move the trigger member from a first position to a second position to initiate the down hole operation. If the primary activation operation fails, a secondary activation operation is performed that initiates the down hole operation without moving the trigger member.
  • the present invention relates to systems and methods used in down hole applications. More particularly, the present invention relates to a secondary or contingency system for initiating a down hole operation such as opening a cementer or setting a down hole tool when a primary system for initiating the down hole operation fails.
  • Systems and methods disclosed herein can be configured as secondary, backup, or contingency systems for performing or initiating various down hole operations, such as setting a down hole tool, cementing, and the like. Other applications will be readily apparent to those skilled in the art.
  • Systems and methods are disclosed that permit the down hole operation to be initiated or performed when the primary system or method for initiating or performing the down hole operation fails to function as desired.
  • the disclosed systems and methods operate using hydraulic pressure and without the use of electronics, signaling, or mechanical means.
  • Some disclosed systems and methods take advantage of a pressure-sensitive rupture member configured to rupture when subjected to a predetermined pressure differential and to thereby permit fluid communication between two chambers that previously had been in substantial fluid isolation.
  • the pressure-sensitive rupture member may be positioned to isolate the interior of a well base pipe from the annular space between the outer surface of the base pipe and the inner surface of the wellbore.
  • the pressure-sensitive rupture member may be configured to rupture in response to a pressure differential that is greater than a pressure differential associated with operation of the primary activation system for initiating the down hole operation.
  • FIG. 1 illustrated is a cross-sectional view of a down hole assembly 10 that includes an exemplary secondary activation system 14 for performing a down hole operation, according to one or more embodiments.
  • the secondary activation system 14 is configured to initiate operation of a multi-stage cementer.
  • the secondary system 14 may also be configured for use in other applications, such as the setting of various down hole tools, including, for example, a casing annulus isolation tool, a multistage tool, formation packer shoes or collars, combinations thereof, or any other down hole tool.
  • the secondary activation system 14 includes a substantially annular sleeve 18 that is moveably positioned within a base pipe 22.
  • the base pipe 22 extends within a wellbore 26 that has been drilled into the Earth's surface to penetrate various earth strata containing, for example, one or more hydrocarbon formations.
  • the system 14 is not limited to use with any specific type of well, but may be used in all types, such as vertical wells, horizontal wells, multilateral (e.g., slanted) wells, combinations thereof, and the like.
  • An optional casing 30 may be disposed within an annulus 34 that is defined between an outer surface 38 of the base pipe 22 and the wellbore 26.
  • the optional casing 30 forms a protective lining within the wellbore 26 and may be made from materials such as metals, plastics, composites, or the like.
  • the casing 30 may be expanded or unexpanded as part of an installation procedure and/or may be segmented or continuous.
  • the base pipe 22 may be run within another, previously set casing string, thereby providing one or more concentric casing strings with annular spaces therebetween.
  • the base pipe 22 may include one or more tubular joints, having metal-to-metal threaded connections or otherwise threadedly joined to form a tubing string. In other embodiments, the base pipe 22 may form a portion of a coiled tubing. The base pipe 22 may also be defined in whole or in part by other types of down hole equipment. The base pipe 22 may have a generally tubular shape and may define an interior 40 surrounded by an inner surface 42. However, other configurations may be suitable, depending on particular conditions and circumstances. For example, some configurations of the base pipe 22 may include offset bores, sidepockets, etc. The base pipe 22 may include portions formed of a non-uniform construction, for example, a joint of tubing having compartments, cavities or other components therein or thereon.
  • the base pipe 22 may be formed of various components, including, but not limited to, a joint casing, a coupling, a lower shoe, a crossover component, or any other component known to those skilled in the art.
  • various elements may be joined via metal-to-metal threaded connections, welded, or otherwise joined to form the base pipe 22.
  • the base pipe 22 may omit elastomeric or other materials subject to aging, and/or attack by environmental chemicals or conditions.
  • the annular sleeve 18 is configured as a pressure-sensitive moveable trigger that functions as a primary activation system for initiating a down hole operation in the wellbore.
  • the sleeve 18 includes a first end 46 having a first area and an opposite second end 50 having a second area that is smaller than the first area.
  • the first and second areas may be axially projected areas obtained by calculating the area of the apparent shape of the sleeve 18 when viewed in the direction of arrow A1 for the first area and in the direction of arrow A2 for the second area.
  • the sleeve 18 includes a substantially constant inner diameter 54 and a stepped outer diameter 58 such that a first portion 62 of the sleeve 18 adjacent the first end 46 may have a greater outer diameter and wall thickness than a second portion 66 of the sleeve 18 adjacent the second end 50.
  • the stepped outer diameter of the sleeve 18 contributes to the resulting difference between the first area and the second area.
  • the outer diameter of the first portion 62 of the sleeve 18 may engage the inner surface 42 of the base pipe 22, and may include a seal 72 positioned therebetween.
  • the outer diameter of the second portion 66 of the sleeve 18 may engage a substantially annular collar 76 that may be fixed with respect to the base pipe 22 such that the sleeve 18 is received by and axially slidable within the collar 76.
  • An additional seal 84 may also be provided between the sleeve 18 and the annular collar 76.
  • the collar 76 is located in an annular space between the second portion 66 of the sleeve 18 and the inner surface 42 of the base pipe 22.
  • One or both of the collar 76 and the sleeve 18 may include additional seals, such as the seal 80, for sealing the engaging surfaces of the collar 76, the sleeve 18, and the base pipe 22.
  • the primary activation system for initiating a down hole operation in the wellbore may also include a force-sensitive and releasable latch for preventing substantial movement of the sleeve 18 with respect to the base pipe 22 until a predetermined force is applied to the sleeve 18.
  • the primary activation system may include a latch in the form of the seals 72 and 84, which may be configured to limit via friction movement of the sleeve 18 with respect to the base pipe 22 until a predetermined force is applied to the sleeve 18.
  • the primary activation system may include one or more shear pins (not shown) having a first end that is fixed with respect to the base pipe 22 and a second end that is fixed with respect to the sleeve 18.
  • a shear lip or other force-sensitive and releasable securing elements may also or alternatively be provided to prevent substantial movement of the sleeve 18 with respect to the base pipe 22 until a predetermined force is applied to the sleeve 18.
  • one or more ports 88 extend through the base pipe 22 and/or through other system components for providing fluid communication between a first chamber, which in the illustrated configuration includes the interior 40 of the base pipe 22 and a second chamber, which in the illustrated configuration includes the annulus 34.
  • the first chamber and the second chamber may be parts of different down hole components.
  • the first chamber may be a chamber that forms a portion of a down hole tool activation assembly (not shown), such as a chamber for setting an annular packer.
  • the sleeve 18 is arranged so that when the sleeve 18 is in a first position (as shown in the Figures), the sleeve 18 blocks the ports 88 and thereby prevents substantial fluid communication between the interior 40 (first chamber) and the annulus 34 (second chamber). As discussed below, during operation of the primary activation system, the sleeve 18 is moveable to a second position ( e.g., shifted to the right in the Figures) to open the ports 88 and thereby allow fluid communication between the interior 40 and the annulus 34 by way of the ports 88.
  • a shutoff plug (not shown), such as a ball, dart, or other blanking device, is landed down hole of the sleeve 18 such that the pressure in the interior 40 of the base pipe 22 can be increased in a controlled manner.
  • Pressure in the interior creates a force differential on the sleeve 18 that tends to move the sleeve 18 axially toward the second end 50 ( e.g., in the direction of the arrow A1). More specifically, because the second end 50 has a smaller area than the first end 46, the pressure in the interior 40 creates a greater force on the first end 46 than the second end 50.
  • the resulting force acting on the sleeve 18 is an axial force that is substantially equal to the pressure in the interior multiplied by the difference between the first area and the second area. Accordingly, the force on the sleeve 18 is proportional to the pressure in the interior 40, and as the pressure in the interior increases, so does the force on the sleeve 18.
  • the releasable latch which in the illustrated embodiment includes seals 72, 84, prevents substantial axial movement of the sleeve 18.
  • the latch is configured to release, e.g., the seals 72, 84 are configured to slip, in response to pressurization of the interior 40 of the base pipe 22 to a predetermined actuation pressure, which in turn applies a predetermined axial force to the sleeve 18.
  • the seals 72, 84 slip and the sleeve 18 moves axially along the base pipe 22 from the first position to the second position when the pressure in the interior 40 reaches the actuation pressure.
  • Movement of the sleeve 18 to the second position opens the ports 88 and allows fluid communication between the interior 40 and the annulus 34. During a cementing operation, this opening of the ports 88 allows cement to flow from the interior 40, through the ports 88, and into the annulus 34.
  • the primary activation system is not 100% reliable. In some instances, pressurizing the interior 40 to the actuation pressure does not move the sleeve 18 from the first position to the second position as desired. As a result, the ports 88 may remain substantially or entirely blocked and fluid communication between the interior 40 and the annulus 34 may therefore remain substantially prevented. It should be appreciated that the illustrated pressure-activated primary activation system with a moveable sleeve 18 is just one example of a primary activation system for performing or initiating a down hole operation. Other activation systems may include electronic motors or actuators and/or different configurations of moveable and non-moveable components for performing a desired task.
  • the secondary activation system 14 can be used to perform or initiate a desired down hole operation when the primary activation system fails or is otherwise inoperable.
  • the secondary activation system 14 may include at least one rupture member 92 positioned in a passageway 96 that extends through the sleeve 18.
  • the passageway 96 may extend from an inner surface 100 to an outer surface 104 of the sleeve 18.
  • the inner surface 100 of the sleeve may be exposed to the interior 40 of the base pipe 22, and the outer surface 104 may face the inner surface 42 of the base pipe 22, including the port 88.
  • the sleeve 18 may include a plurality of passageways 96, and each passageway 96 may receive or otherwise have arranged therein a respective rupture member 92. In some configurations, the sleeve 18 is oriented in the base pipe 22 such that at least one of the passageways 96 is substantially aligned with a corresponding one of the ports 88 in the base pipe 22.
  • the rupture member 92 may rupture when subjected to a predetermined threshold pressure differential, and rupturing of the rupture member 92 may in turn establish fluid communication between the interior 40 of the base pipe 22 and the annulus 34 by way of the passageway 96 and the port 88, thereby initiating the down hole operation.
  • the rupture member 92 may be or include, among other things, a burst disk, an elastomeric seal, a metal seal, a plate having an area of reduced cross section, a pivoting member held in a closed position by shear pins designed to fail in response to a predetermined shear load, an engineered component having built-in stress risers of a particular configuration, and/or substantially any other component that is specifically designed to rupture or fail in a controlled manner when subjected to a predetermined threshold pressure differential.
  • the rupture member 92 may be configured as a one-way rupture member that only ruptures when elevated pressure is applied to a specific side of the rupture member 92.
  • the rupture member 92 functions substantially as a seal between isolated chambers only until a pressure differential between the isolated chambers reaches the predetermined threshold value, at which point the rupture member fails, bursts, or otherwise opens to allow fluid to flow from the chamber at higher pressure into the chamber at lower pressure.
  • the specific size, type, and configuration of the rupture member 92 generally is chosen so the rupture member 92 will rupture at a desired pressure differential.
  • the rupture member 92 is exposed to the interior 40 of the base pipe 22 and to the annulus 34 by way of the port 88. More specifically, a first side of the rupture member 92 is exposed to the interior 40, and a second side of the rupture member 92 is exposed to the annulus 34 due to the open fluid communication provided between the annulus and the rupture member 92 by the port 88 in the base pipe 22. When intact, the rupture member 92 delimits the interior 40 from the annulus 34. Accordingly, the rupture member 92 is located in the passageway 96 and acts as a seal between the interior 40 and the annulus when the rupture member 92 is intact.
  • the rupture member 92 is configured or selected such that the threshold pressure differential at which the rupture member 92 ruptures is greater than a pressure differential across the rupture member 92 when the interior 40 of the base pipe 22 is pressurized to the activation pressure associated with the primary activation system. In this way, during attempts to operate the primary activation system, for example, by pressurizing the interior 40 to the activation pressure to move the sleeve 18 from the first position to the second position, the rupture member or members 92 remain intact. If the primary activation system fails, e.g., if the sleeve 18 fails to move as desired, an operator can further pressurize the interior 40 until the threshold pressure differential is reached and the rupture member 92 ruptures.
  • the secondary activation system allows for initiation of the down hole operation without moving the sleeve 18.
  • some configurations of the sleeve 18 include one or more channels 108 that communicate with one or more of the passageways 96.
  • the channels 108 can reduce the number of rupture members 92 utilized on a given sleeve 18 by communicating the passageways 96 in the sleeve 18 with more than one port 88 in the base pipe 22.
  • the sleeve 18 can be oriented such that at least some of the passageways 96 are substantially aligned with a corresponding one of the ports 88.
  • the base pipe 22 may include several ports 88 circumferentially spaced about the base pipe 22.
  • the channels 108 can be formed on or in the sleeve 18 such that fluid flow through one passageway 96 can be routed to more than one port 88.
  • a channel 108 includes an axially extending portion 108a that intersects and communicates with one of the passageways 96 formed in the sleeve 18.
  • the axially extending portion 108a extends away from the passageway 96 and intersects a circumferentially extending portion 108b of the channel 108.
  • the circumferentially extending portion of the channel 108 extends along a portion of the sleeve 18 and intersects another axially extending portion 108c.
  • the illustrated axially extending portion 108c does not communicate or intersect with a passageway 96, but rather is positioned for alignment with one of the ports (not shown) on the base pipe 22.
  • fluid flowing through the passageway 96 shown in Fig. 3 can be communicated to a first port 88 that is substantially aligned with the passageway 96 as well as to a second port 88 that is aligned with the axially extending channel portion 108c.
  • the channel 108 can be configured to provide fluid communication to several ports 88, and several channels 108 can be provided to accommodate various configurations of passageways 96 and ports 88.
  • the channel 108 is formed as a recess in the outer surface 104 of the sleeve 18.
  • the channel 108 can be formed as a closed channel or bore through the sleeve 18 or through other components included in one or both of the first and second activation systems.
  • the channel or channels 108 function such that, when the rupture member 92 ruptures, fluid from the interior 40 can flow through the channels 108 to those ports 88 in the base pipe 22 that are not necessarily aligned with one of the passageways 96 in the sleeve 18.

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Claims (10)

  1. System zum Einleiten eines untertägigen Vorgangs in einem Bohrloch, wobei das System Folgendes umfasst:
    eine ringförmigen Hülse (18) mit einer Innenfläche (100), einer Außenfläche (104), einem ersten Ende (46) und einem zweiten Ende (50), wobei die ringförmige Hülse (18) einen Durchlass (96) definiert, der sich zwischen der Innenfläche (100) und der Außenfläche (104) erstreckt, wobei wenigstens ein Abschnitt der ringförmigen Hülse (18) dazu konfiguriert ist, sich während eines primären Aktivierungsvorgangs zu bewegen, um den untertägigen Vorgang einzuleiten; dadurch gekennzeichnet, dass das System ferner Folgendes umfasst:
    ein Berstelement (92), das in dem Durchlass (96) angeordnet und dazu konfiguriert ist, den untertägigen Vorgang einzuleiten, wenn der primäre Aktivierungsvorgang fehlschlägt, wobei das Berstelement (92) eine Schwellendruckdifferenz aufweist, bei der das Berstelement (92) birst, um Fluidfluss durch den Durchlass zuzulassen und dadurch den untertägigen Vorgang einzuleiten,
    wobei wenigstens ein Kanal in der ringförmigen Hülse (18) definiert ist und sich in Umfangsrichtung um wenigstens einen Abschnitt der ringförmigen Hülse (18) erstreckt, wobei der wenigstens eine Kanal in Fluidverbindung mit dem Durchlass (96) steht.
  2. System nach Anspruch 1, wobei der gesamte Körper für eine Bewegung während des primären Aktivierungsvorgangs konfiguriert ist.
  3. System nach Anspruch 2, wobei das erste Ende einen axial vorspringenden ersten Bereich beinhaltet, der größer als ein axial vorspringender zweiter Bereich des zweiten Endes ist, und wobei der primäre Aktivierungsvorgang Aussetzen der ringförmigen Hülse (18) gegenüber einem Aktivierungsdruck beinhaltet, der dazu konfiguriert ist, die ringförmige Hülse (18) axial im Bohrloch zu bewegen, und wobei der primäre Aktivierungsvorgang fehlschlägt, wenn die ringförmige Hülse (18) sich nicht axial bewegt, wenn sie dem ersten Aktivierungsdruck ausgesetzt wird.
  4. System nach Anspruch 2 oder 3, wobei die Schwellendruckdifferenz größer als eine Aktivierungsdruckdifferenz an dem Berstelement (92) und im Zusammenhang mit dem Aktivierungsdruck ist.
  5. System nach Anspruch 1, wobei der wenigstens eine Kanal eine Vertiefung in einer Außenfläche des Körpers ist.
  6. System nach Anspruch 1, wobei der wenigstens eine Kanal einen ersten Abschnitt, der sich in Umfangsrichtung um wenigstens einen Abschnitt des Körpers erstreckt, und einen zweiten Abschnitt beinhaltet, der sich axial zwischen dem Durchlass und dem ersten Abschnitt erstreckt.
  7. Verfahren zum Einleiten eines untertägigen Vorgangs in einem Bohrloch, wobei das Verfahren Folgendes umfasst:
    Anordnen einer ringförmigen Hülse (18) im Bohrloch, wie in einem Basisrohr (22) mit einer oder mehreren darin definierten Öffnungen (88) angeordnet, um eine Fluidverbindung zwischen einem Inneren des Basisrohrs (22) und einem Ringraum (34) zu ermöglichen, der das Basisrohr (22) umgibt;
    Durchführen eines primären Aktivierungsvorgangs, der dazu konfiguriert ist, das ringförmige Hülsenelement (18) aus einer ersten Position, in der die ringförmige Hülse die eine oder die mehreren Öffnungen (88) blockiert, in eine zweite Position zu bewegen, in der die eine oder die mehreren Öffnungen (88) freiliegen, um den untertägigen Vorgang einzuleiten; und
    wenn der primäre Aktivierungsvorgang fehlschlägt, Durchführen eines sekundären Aktivierungsvorgangs, der den untertägigen Vorgang einleitet, ohne die ringförmige Hülse (18) zu bewegen, wobei der sekundäre Aktivierungsvorgang das Berstenlassen eines Berstelements (92) beinhaltet, das in einem Durchlass (96) angeordnet ist, der in der ringförmigen Hülse (18) definiert ist und sich zwischen dem Inneren des Basisrohrs (22) und dem Ringraum (34) erstreckt, und wobei das Berstelement (92) eine erste Seite aufweist, die zum Inneren freiliegt, wobei eine zweite Seite zum Ringraum (34) freiliegt.
  8. Verfahren nach Anspruch 7, wobei das Durchführen des primären Aktivierungsvorgangs das Steigern eines Drucks im Inneren des Basisrohrs auf einen Aktivierungsdruck beinhaltet, wobei die ringförmige Hülse dazu konfiguriert ist, sich in die zweite Position zu bewegen, wenn sie dem Aktivierungsdruck ausgesetzt wird.
  9. Verfahren nach Anspruch 8, wobei das Durchführen des sekundären Aktivierungsvorgangs das Steigern des Innendrucks im Bohrloch auf einen Schwellendruck beinhaltet, der größer als der Aktivierungsdruck ist.
  10. Verfahren nach Anspruch 7, wobei das Einleiten des untertägigen Vorgangs ferner das Herstellen einer Fluidverbindung zwischen dem Inneren des Basisrohrs (22) und dem Ringraum (34) beinhaltet.
EP13840432.2A 2012-09-27 2013-09-25 Sekundäres system und verfahren zum aktivieren einer bohrlochvorrichtung Active EP2900900B1 (de)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US13/628,955 US9027653B2 (en) 2012-09-27 2012-09-27 Secondary system and method for activating a down hole device
PCT/US2013/061600 WO2014052404A1 (en) 2012-09-27 2013-09-25 Secondary system and method for activating a down hole device

Publications (3)

Publication Number Publication Date
EP2900900A1 EP2900900A1 (de) 2015-08-05
EP2900900A4 EP2900900A4 (de) 2016-07-27
EP2900900B1 true EP2900900B1 (de) 2017-11-29

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EP13840432.2A Active EP2900900B1 (de) 2012-09-27 2013-09-25 Sekundäres system und verfahren zum aktivieren einer bohrlochvorrichtung

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US (1) US9027653B2 (de)
EP (1) EP2900900B1 (de)
AU (1) AU2013323704B2 (de)
BR (1) BR112015004954A2 (de)
CA (1) CA2884123C (de)
MX (1) MX355099B (de)
NO (1) NO2959096T3 (de)
WO (1) WO2014052404A1 (de)

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US9027653B2 (en) 2012-09-27 2015-05-12 Halliburton Energy Services, Inc. Secondary system and method for activating a down hole device
US9243480B2 (en) 2012-10-31 2016-01-26 Halliburton Energy Services, Inc. System and method for activating a down hole tool
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US10400534B2 (en) 2015-05-28 2019-09-03 Halliburton Energy Services, Inc. Viscous damping systems for hydrostatically set downhole tools

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Also Published As

Publication number Publication date
EP2900900A4 (de) 2016-07-27
MX2015002617A (es) 2016-01-22
BR112015004954A2 (pt) 2017-07-04
CA2884123C (en) 2016-10-18
AU2013323704A1 (en) 2015-03-12
CA2884123A1 (en) 2014-04-03
EP2900900A1 (de) 2015-08-05
NO2959096T3 (de) 2018-10-13
AU2013323704B2 (en) 2015-12-10
WO2014052404A1 (en) 2014-04-03
US9027653B2 (en) 2015-05-12
US20140083713A1 (en) 2014-03-27
MX355099B (es) 2018-04-05

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